Organic Acid Compositions and Methods of Use in Subterranean Operations

ABSTRACT

Subterranean treatment fluids comprising one or more organic acids and methods of use in subterranean operations are provided. In one embodiment, the methods comprise: providing a treatment fluid that comprises an aqueous base fluid, a plurality of particulates, a gelling agent, and one or more organic acids; introducing the treatment fluid into at least a portion of a subterranean formation; and depositing at least a portion of the particulates in a portion of the subterranean formation so as to form a gravel pack in a portion of the subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of U.S. patent applicationSer. No. 11/352,744, entitled “Organic Acid Compositions and Methods ofUse in Subterranean Operations,” filed on Feb. 10, 2006, the entirity ofwhich is herein incorporated by reference.

BACKGROUND

The present invention relates to fluids useful in subterraneanoperations. More specifically, the present invention relates tosubterranean treatment fluids comprising one or more organic acids andmethods of use in subterranean operations.

Treatment fluids may be used in a variety of subterranean treatments,including, but not limited to, stimulation treatments and sand controltreatments. As used herein, the term “treatment,” or “treating,” refersto any subterranean operation that uses a fluid in conjunction with adesired function and/or for a desired purpose. The terms “treatment,”and “treating,” as used herein, do not imply any particular action bythe fluid or any particular component thereof.

One common production stimulation operation that employs a treatmentfluid is hydraulic fracturing. Hydraulic fracturing operations generallyinvolve pumping a treatment fluid (e.g., a fracturing fluid) into a wellbore that penetrates a subterranean formation at a sufficient hydraulicpressure to create or enhance one or more cracks, or “fractures,” in thesubterranean formation. “Enhancing” one or more fractures in asubterranean formation, as that term is used herein, is defined toinclude the extension or enlargement of one or more natural orpreviously created fractures in the subterranean formation. Thetreatment fluid may comprise particulates, often referred to as“proppant particulates,” that are deposited in the fractures. Theproppant particulates, inter alia, may prevent the fractures from fullyclosing upon the release of hydraulic pressure, forming conductivechannels through which fluids may flow to the well bore. Once at leastone fracture is created and the proppant particulates are substantiallyin place, the treatment fluid may be “broken” (i.e., the viscosity ofthe fluid is reduced), and the treatment fluid may be recovered from theformation.

Other common production stimulation operations that employ treatmentfluids are acidizing operations. Where the subterranean formationcomprises acid-soluble components, such as those present in carbonateand sandstone formations, stimulation is often achieved by contactingthe formation with a treatment fluid that comprises an acid. Forexample, where hydrochloric acid contacts and reacts with calciumcarbonate in a formation, the calcium carbonate is consumed to producewater, carbon dioxide, and calcium chloride. After acidization iscompleted, the water and salts dissolved therein may be recovered byproducing them to the surface (e.g., “flowing back” the well), leaving adesirable amount of voids (e.g., wormholes) within the formation, whichmay enhance the formation's permeability and/or increase the rate atwhich hydrocarbons subsequently may be produced from the formation. Onemethod of acidizing known as “fracture acidizing” comprises injecting atreatment fluid that comprises an acid into the formation at a pressuresufficient to create or enhance one or more fractures within thesubterranean formation. Another method of acidizing known as “matrixacidizing” comprises injecting a treatment fluid that comprises an acidinto the formation at a pressure below that which would create orenhance one or more fractures within the subterranean formation.

Treatment fluids are also utilized in sand control treatments, such asgravel packing. In “gravel-packing” treatments, a treatment fluidsuspends particulates (commonly referred to as “gravel particulates”),and deposits at least a portion of those particulates in a desired areain a well bore, e.g., near unconsolidated or weakly consolidatedformation zones, to form a “gravel pack,” which is a grouping ofparticulates that are packed sufficiently close together so as toprevent the passage of certain materials through the gravel pack. This“gravel pack” may, inter alia, enhance sand control in the subterraneanformation and/or prevent the flow of particulates from an unconsolidatedportion of the subterranean formation (e.g., a propped fracture) into awell bore. One common type of gravel-packing operation involves placinga sand control screen in the well bore and packing the annulus betweenthe screen and the well bore with the gravel particulates of a specificsize designed to prevent the passage of formation sand. The gravelparticulates act, inter alia, to prevent the formation sand fromoccluding the screen or migrating with the produced hydrocarbons, andthe screen acts, inter alia, to prevent the particulates from enteringthe well bore. Once the gravel pack is substantially in place, theviscosity of the treatment fluid may be reduced to allow it to berecovered. In some situations, fracturing and gravel-packing treatmentsare combined into a single treatment (commonly referred to as FRACPAC™operations). In such FRACPAC™ operations, the treatments are generallycompleted with a gravel pack screen assembly in place with the hydraulicfracturing treatment being pumped through the annular space between thecasing and screen. In this situation, the hydraulic fracturing treatmentends in a screen-out condition, creating an annular gravel pack betweenthe screen and casing. In other cases, the fracturing treatment may beperformed prior to installing the screen and placing a gravel pack.

Maintaining sufficient viscosity in the treatment fluids used in theseoperations is important for a number of reasons. Maintaining sufficientviscosity is important in fracturing and sand control treatments forparticulate transport and/or to create or enhance fracture width. Also,maintaining sufficient viscosity may be important to control and/orreduce fluid loss into the formation. At the same time, whilemaintaining sufficient viscosity of the treatment fluid often isdesirable, it may also be desirable to maintain the viscosity of thetreatment fluid in such a way that the viscosity also may be reducedeasily at a particular time, inter alia, for subsequent recovery of thefluid from the formation.

To provide the desired viscosity, polymeric gelling agents commonly areadded to the treatment fluids. The term “gelling agent” is definedherein to include any substance that is capable of increasing theviscosity of a fluid, for example, by forming a gel. Examples ofcommonly used polymeric gelling agents include, but are not limited to,guar gums and derivatives thereof, cellulose derivatives, biopolymers,and the like. To further increase the viscosity of a treatment fluid,often the gelling agent is crosslinked with the use of a crosslinkingagent. Conventional crosslinking agents may comprise a borate ion, ametal ion, or the like, and interact with at least two gelling agentmolecules to form a crosslink between them, thereby forming a“crosslinked gelling agent.” Treatment fluids comprising crosslinkedgelling agents also may exhibit elastic or viscoelastic properties,wherein the crosslinks between gelling agent molecules may be broken andreformed, allowing the viscosity of the fluid to vary with certainconditions such as temperature, pH, and the like.

However, the use of conventional gelling agents may be problematic incertain subterranean formations exhibiting high temperatures (e.g.,above about 200° F.). Many conventional gelling agents become unstableat these temperatures, which reduces the viscosity of the treatmentfluid. This inability to maintain a desired level of viscosity at highertemperatures, among other problems, may increase fluid loss and decreasethe ability of the fluid to suspend and/or transport particulatematerials.

Inorganic acids and/or salts thereof have been added to subterraneantreatment fluids used heretofore in the art for a variety ofsubterranean treatments, for example, in acidizing treatments. However,the use of inorganic acids may be problematic. For example, certaininorganic acids may corrode equipment placed in the subterraneanformation. Certain inorganic acids also may thermally or hydrolyticallydegrade, or otherwise be incompatible with certain types of gellingagents (e.g., naturally-occurring polymers). To solve these problems inacidizing treatments, organic acids have been included in acidizingtreatment fluids for their improved dissolving abilities and relativelylow rates of corrosion at higher temperatures. Organic acid salts havebeen used in treatment fluids in a variety of subterranean operations,among other purposes, to improve the viscosity of the fluids. However,the use of organic acids has been limited heretofore to acidizingapplications.

SUMMARY

The present invention relates to fluids useful in subterraneanoperations. More specifically, the present invention relates tosubterranean treatment fluids comprising one or more organic acids andmethods of use in subterranean operations.

In one embodiment, the present invention provides a method comprising:providing a treatment fluid that comprises an aqueous base fluid, agelling agent, and one or more organic acids; and contacting asubterranean formation with the treatment fluid at or above a pressuresufficient to create or enhance one or more fractures in a portion ofthe subterranean formation.

In another embodiment, the present invention provides a methodcomprising: providing a treatment fluid that comprises an aqueous basefluid, a plurality of particulates, a gelling agent, and one or moreorganic acids; introducing the treatment fluid into at least a portionof a subterranean formation; and depositing at least a portion of theparticulates in a portion of the subterranean formation so as to form agravel pack in a portion of the subterranean formation.

In another embodiment, the present invention provides a methodcomprising: providing a treatment fluid that comprises an aqueous basefluid, a gelling agent, one or more organic acids or salts thereof, andone or more inorganic acids or salts thereof; and allowing at least aportion of the treatment fluid to react with at least a portion of asubterranean formation so that at least one void is formed in thesubterranean formation.

In another embodiment, the present invention provides a methodcomprising: providing a treatment fluid that comprises an aqueous basefluid, a gelling agent, and one or more organic acids or salts thereof;introducing the treatment fluid into a subterranean formation; andallowing the treatment fluid to suspend one or more particulates in thesubterranean formation.

The features and advantages of the present invention will be apparent tothose skilled in the art. While numerous changes may be made by thoseskilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 illustrates some data regarding the viscosity of varioustreatment fluids, including certain embodiments of the treatment fluidsof the present invention.

FIG. 2 illustrates some data regarding the viscosity of varioustreatment fluids, including certain embodiments of the treatment fluidsof the present invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to fluids useful in subterraneanoperations. More specifically, the present invention relates tosubterranean treatment fluids comprising one or more organic acids andmethods of use in subterranean operations.

The present invention generally involves the use of treatment fluidsthat comprise an aqueous base fluid, a gelling agent, and one or moreorganic acids (and/or, in some embodiments, a salt thereof). The term“gelling agent” is defined herein to include any substance that iscapable of increasing the viscosity of a fluid, for example, by forminga gel. The term “organic acid” is defined herein to include any acidiccompound that comprises one or more carbon atoms. A “salt” of an organicacid, as that term is used herein, refers to any compound that sharesthe same base formula as a referenced organic acid, except that one ofthe hydrogen cations thereon is replaced by a different cation. Thetreatment fluids of the present invention are thought to, inter alia,maintain higher viscosities (e.g., above about 20 centipoises (“cP”))for longer periods of time and/or at higher temperatures thanconventional treatment fluids, which may enable improved fluid lossprevention, particulate transport, hydraulic fracturing efficiency, andthe like in subterranean operations employing these treatment fluids.

The aqueous base fluids used in the treatment fluids of the presentinvention may comprise fresh water, saltwater (e.g., water containingone or more salts dissolved therein), brine, seawater, or combinationsthereof. Generally, the water may be from any source, provided that itdoes not contain components that might adversely affect the stabilityand/or performance of the treatment fluids of the present invention. Incertain embodiments, the density of the aqueous base fluid can beadjusted, among other purposes, to provide additional particle transportand suspension in the treatment fluids of the present invention. Incertain embodiments, the pH of the aqueous base fluid may be adjusted(e.g., by a buffer or other pH adjusting agent), among other purposes,to activate a crosslinking agent and/or to reduce the viscosity of thetreatment fluid (e.g., activate a breaker, deactivate a crosslinkingagent). In these embodiments, the pH may be adjusted to a specificlevel, which may depend on, among other factors, the types of gellingagents, acids, and other additives included in the treatment fluid. Oneof ordinary skill in the art, with the benefit of this disclosure, willrecognize when such density and/or pH adjustments are appropriate.

The gelling agents used in the present invention may comprise anysubstance (e.g. a polymeric material) capable of increasing theviscosity of a fluid. In certain embodiments, the gelling agent maycomprise polymers that have at least two molecules that are capable offorming a crosslink in a crosslinking reaction in the presence of acrosslinking agent, and/or polymers that have at least two moleculesthat are so crosslinked (i.e., a crosslinked gelling agent). The gellingagents may be naturally-occurring gelling agents, synthetic gellingagents, or a combination thereof. The gelling agents also may becationic gelling agents, anionic gelling agents, or a combinationthereof. In certain embodiments, suitable gelling agents may comprisepolysaccharides, biopolymers, and/or derivatives thereof that containone or more of these monosaccharide units: galactose, mannose,glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, orpyranosyl sulfate. The term “derivative,” as used herein, includes anycompound that is made from one of the listed compounds, for example, byreplacing one atom in the listed compound with another atom or group ofatoms, rearranging two or more atoms in the listed compound, ionizingone of the listed compounds, or creating a salt of one of the listedcompounds. Examples of suitable polysaccharides include, but are notlimited to, guar gums (e.g., hydroxyethyl guar, hydroxypropyl guar,carboxymethyl guar, carboxymethylhydroxyethyl guar, andcarboxymethylhydroxypropyl guar (“CMHPG”)), cellulose derivatives (e.g.,hydroxyethyl cellulose, carboxyethylcellulose, carboxymethylcellulose,and carboxymethylhydroxyethylcellulose), xanthan, scleroglucan, diutan,and combinations thereof. In certain embodiments, the gelling agentscomprise an organic carboxylated polymer, such as CMHPG.

Suitable synthetic polymers include, but are not limited to,2,2′-azobis(2,4-dimethyl valeronitrile),2,2′-azobis(2,4-dimethyl-4-methoxy valeronitrile), polymers andcopolymers of acrylomide ethyltrimethyl ammonium chloride, acrylamide,acrylamido-and methacrylamido-alkyl trialkyl ammonium salts,acrylamidomethylpropane sulfonic acid, acrylamidopropyl trimethylammonium chloride, acrylic acid, dimethylaminoethyl methacrylamide,dimethylaminoethyl methacrylate, dimethylaminopropyl methacrylamide,dimethylaminopropylmethacrylamide, dimethyldiallylammonium chloride,dimethylethyl acrylate, fumaramide, methacrylamide, methacrylamidopropyltrimethyl ammonium chloride,methacrylamidopropyldimethyl-n-dodecylammonium chloride,methacrylamidopropyldimethyl-n-octylammonium chloride,methacrylamidopropyltrimethylammonium chloride, methacryloylalkyltrialkyl ammonium salts, methacryloylethyl trimethyl ammonium chloride,methacrylylamidopropyldimethylcetylammonium chloride,N-(3-sulfopropyl)-N-methacrylamidopropyl-N,N-dimethyl ammonium betaine,N,N-dimethylacrylamide, N-methylacrylamide,nonylphenoxypoly(ethyleneoxy)ethylmethacry late, partially hydrolyzedpolyacrylamide, poly 2-amino-2-methyl propane sulfonic acid, polyvinylalcohol, sodium 2-acrylamido-2-methylpropane sulfonate, quaternizeddimethylaminoethylacrylate, quaternized dimethylaminoethylmethacrylate,and mixtures and derivatives thereof. In certain embodiments, thegelling agent comprises anacrylamide/2-(methacryloyloxy)ethyltrimethylammonium methyl sulfatecopolymer. In certain embodiments, the gelling agent may comprise anacrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloride copolymer.In certain embodiments, the gelling agent may comprise a derivatizedcellulose that comprises cellulose grafted with an allyl or a vinylmonomer, such as those disclosed in U.S. Pat. Nos. 4,982,793, 5,067,565,and 5,122,549, the relevant disclosures of which are incorporated hereinby reference.

Additionally, polymers and copolymers that comprise one or morefunctional groups (e.g., hydroxyl, cis-hydroxyl, carboxylic acids,derivatives of carboxylic acids, sulfate, sulfonate, phosphate,phosphonate, amino, or amide groups) may be used as gelling agents.

The gelling agent may be present in the treatment fluids of the presentinvention in an amount sufficient to provide the desired viscosity. Insome embodiments, the gelling agents (i.e., the polymeric material) maybe present in an amount in the range of from about 0.1% to about 10% byweight of the treatment fluid. In certain embodiments, the gellingagents may be present in an amount in the range of from about 0.15% toabout 2.5% by weight of the treatment fluid.

In those embodiments of the present invention where it is desirable tocrosslink the gelling agent, the treatment fluid may comprise one ormore of the crosslinking agents. The crosslinking agents may comprise aborate, a metal ion, or similar component that is capable ofcrosslinking at least two molecules of the gelling agent. Examples ofsuitable crosslinking agents include, but are not limited to, borateions, magnesium ions, zirconium IV ions, titanium IV ions, aluminumions, antimony ions, chromium ions, iron ions, copper ions, magnesiumions, and zinc ions. These ions may be provided by providing anycompound that is capable of producing one or more of these ions.Examples of such compounds include, but are not limited to, ferricchloride, boric acid, disodium octaborate tetrahydrate, sodium diborate,pentaborates, ulexite, colemanite, magnesium oxide, zirconium lactate,zirconium triethanol amine, zirconium lactate triethanolamine, zirconiumcarbonate, zirconium acetylacetonate, zirconium malate, zirconiumcitrate, zirconium diisopropylamine lactate, zirconium glycolate,zirconium triethanol amine glycolate, zirconium lactate glycolate,titanium lactate, titanium malate, titanium citrate, titanium ammoniumlactate, titanium triethanolamine, and titanium acetylacetonate,aluminum lactate, aluminum citrate, antimony compounds, chromiumcompounds, iron compounds, copper compounds, zinc compounds, andcombinations thereof. In certain embodiments of the present invention,the crosslinking agent may be formulated to remain inactive until it is“activated” by, among other things, certain conditions in the fluid(e.g., pH, temperature, etc.) and/or interaction with some othersubstance. In some embodiments, the crosslinking agent may be delayed byencapsulation with a coating (e.g., a porous coating through which thecrosslinking agent may diffuse slowly, or a degradable coating thatdegrades downhole) that delays the release of the crosslinking agentuntil a desired time or place. The choice of a particular crosslinkingagent will be governed by several considerations that will be recognizedby one skilled in the art, including but not limited to the following:the type of gelling agent included, the molecular weight of the gellingagent(s), the conditions in the subterranean formation being treated,the safety handling requirements, the pH of the treatment fluid,temperature, and/or the desired delay for the crosslinking agent tocrosslink the gelling agent molecules.

When included, suitable crosslinking agents may be present in thetreatment fluids of the present invention in an amount sufficient toprovide, inter alia, the desired degree of crosslinking betweenmolecules of the gelling agent. In certain embodiments, the crosslinkingagent may be present in the treatment fluids of the present invention inan amount in the range of from about 0.0005% to about 1% by weight ofthe treatment fluid. In certain embodiments, the crosslinking agent maybe present in the treatment fluids of the present invention in an amountin the range of from about 0.005% to about 1% by weight of the treatmentfluid. One of ordinary skill in the art, with the benefit of thisdisclosure, will recognize the appropriate amount of crosslinking agentto include in a treatment fluid of the present invention based on, amongother things, the temperature conditions of a particular application,the type of gelling agents used, the molecular weight of the gellingagents, the desired degree of viscosification, and/or the pH of thetreatment fluid.

The organic acids used in the present invention may comprise any acidiccompound that comprises one or more carbon atoms. Examples of suitableorganic acids include, but are not limited to, formic acid, acetic acid,citric acid, glycolic acid, lactic acid, and 3-hydroxypropionic acid.Alternatively or in combination with one or more organic acids, thetreatment fluids of the present invention may comprise a salt of anorganic acid. A “salt” of an acid, as that term is used herein, refersto any compound that shares the same base formula as the referencedacid, but one of the hydrogen cations thereon is replaced by a differentcation (e.g., an antimony, bismuth, potassium, sodium, calcium,magnesium, cesium, or zinc cation). Examples of suitable salts oforganic acids include, but are not limited to, sodium acetate, sodiumformate, calcium acetate, calcium formate, cesium acetate, cesiumformate, potassium acetate, potassium formate, magnesium acetate,magnesium formate, zinc acetate, zinc formate, antimony acetate,antimony formate, bismuth acetate, and bismuth formate. The treatmentfluids of the present invention may comprise any combination of organicacids and/or salts thereof. The one or more organic acids (or saltsthereof) may be present in the treatment fluids of the present inventionin an amount sufficient to provide the desired viscosity. In someembodiments, the one or more organic acids (or salts thereof) may bepresent in an amount in the range of from about 0.001% by weight of thetreatment fluid to the saturation level of the treatment fluid. Incertain embodiments, the one or more organic acids (or salts thereof)may be present in an amount in the range of from about 1% by weight ofthe treatment fluid to the saturation level of the treatment fluid. Theamount of the organic acid(s) (or salts thereof) included in aparticular treatment fluid of the present invention may depend upon theparticular acid and/or salt used, as well as other components of thetreatment fluid, and/or other factors that will be recognized by one ofordinary skill in the art.

In certain embodiments, the treatment fluids of the present inventionoptionally may comprise one or more inorganic acids (or salts thereof,as that term is defined above). The term “inorganic acid” refers to anyacidic compound that does not comprise a carbon atom. Examples ofsuitable inorganic acids include, but are not limited to, hydrochloricacid, hydrofluoric acid, hydrobromic acid, sulfuric acid, phosphoricacid, and nitric acid. Examples of suitable salts of inorganic acidsinclude, but are not limited to, sodium chloride, calcium chloride,potassium chloride, sodium bromide, calcium bromide, potassium bromide,sodium sulfate, calcium sulfate, sodium phosphate, calcium phosphate,sodium nitrate, calcium nitrate, cesium chloride, cesium sulfate, cesiumphosphate, cesium nitrate, cesium bromide, potassium sulfate, potassiumphosphate, potassium nitrate, and the like. When included, the treatmentfluids of the present invention may comprise any combination ofinorganic acids and/or salts thereof. The one or more inorganic acids(or salts thereof) may be present in the treatment fluids of the presentinvention in an amount sufficient to provide the desired viscosity. Insome embodiments, the one or more inorganic acids (or salts thereof) maybe present in an amount in the range of from about 1% by weight of thetreatment fluid to the saturation level of the treatment fluid, whichmay depend upon the particular acid and/or salt used, as well as othercomponents of the treatment fluid.

The treatment fluids of the present invention optionally may compriseparticulates, such as proppant particulates or gravel particulates.Particulates suitable for use in the present invention may comprise anymaterial suitable for use in subterranean operations. Suitable materialsfor these particulates include, but are not limited to, sand, bauxite,ceramic materials, glass materials, polymer materials, TEFLON®materials, nut shell pieces, cured resinous particulates comprising nutshell pieces, seed shell pieces, cured resinous particulates comprisingseed shell pieces, fruit pit pieces, cured resinous particulatescomprising fruit pit pieces, wood, composite particulates, andcombinations thereof. Suitable composite particulates may comprise abinder and a filler material wherein suitable filler materials includesilica, alumina, fumed carbon, carbon black, graphite, mica, titaniumdioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron,fly ash, hollow glass microspheres, solid glass, and combinationsthereof. The mean particulate size generally may range from about 2 meshto about 400 mesh on the U.S. Sieve Series; however, in certaincircumstances, other mean particulate sizes may be desired and will beentirely suitable for practice of the present invention. In particularembodiments, preferred mean particulates size distribution ranges areone or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or50/70 mesh. It should be understood that the term “particulate,” as usedin this disclosure, includes all known shapes of materials, includingsubstantially spherical materials, fibrous materials, polygonalmaterials (such as cubic materials), and mixtures thereof. Moreover,fibrous materials, that may or may not be used to bear the pressure of aclosed fracture, may be included in certain embodiments of the presentinvention. In certain embodiments, the particulates included in thetreatment fluids of the present invention may be coated with anysuitable resin or tackifying agent known to those of ordinary skill inthe art. In certain embodiments, the particulates may be present in thetreatment fluids of the present invention in an amount in the range offrom about 0.5 pounds per gallon (“ppg”) to about 30 ppg by volume ofthe treatment fluid.

The treatment fluids of the present invention also may include internalgel breakers such as enzyme, oxidizing, acid buffer, or delayed gelbreakers. The gel breakers may cause the treatment fluids of the presentinvention to revert to thin fluids that can be produced back to thesurface, for example, after they have been used to place proppantparticles in subterranean fractures. In some embodiments, the gelbreaker may be formulated to remain inactive until it is “activated” by,among other things, certain conditions in the fluid (e.g. pH,temperature, etc.) and/or interaction with some other substance. In someembodiments, the gel breaker may be delayed by encapsulation with acoating (e.g. a porous coatings through which the breaker may diffuseslowly, or a degradable coating that degrades downhole.) That delays therelease of the gel breaker. In certain embodiments, the gel breaker usedmay be present in the treatment fluid in an amount in the range of fromabout 0.0001% to about 200% by weight of the gelling agent. One ofordinary skill in the art, with the benefit of this disclosure, willrecognize the type and amount of a gel breaker to include in certaintreatment fluids of the present invention based on, among other factors,the desired amount of delay time before the gel breaks, the type ofgelling agents used, the temperature conditions of a particularapplication, the desired rate and degree of viscosity reduction, and/orthe pH of the treatment fluid.

The treatment fluids of the present invention optionally may include oneor more of a variety of well-known additives, such as gel stabilizers,fluid loss control additives, scale inhibitors, corrosion inhibitors,catalysts, clay stabilizers, biocides, bactericides, friction reducers,gases, foaming agents, surfactants, iron control agents, solubilizers,pH adjusting agents (e.g., buffers), and the like. For example, in someembodiments, it may be desired to foam a treatment fluid of the presentinvention using a gas, such as air, nitrogen, or carbon dioxide. Thoseof ordinary skill in the art, with the benefit of this disclosure, willbe able to determine the appropriate additives for a particularapplication.

The treatment fluids of the present invention may be prepared by anymethod suitable for a given application. For example, certain componentsof the treatment fluid of the present invention (e.g., crosslinkablepolymers, biopolymers, etc.) may be provided in a pre-blended powder,which may be combined with the aqueous base fluid at a subsequent time.In preparing the treatment fluids of the present invention, the pH ofthe aqueous base fluid may be adjusted, among other purposes, tofacilitate the hydration of the gelling agent. The pH range in which thegelling agent will readily hydrate may depend upon a variety of factors(e.g., the components of the gelling agent, etc.) that will berecognized by one skilled in the art. This adjustment of pH may occurprior to, during, or subsequent to the addition of the gelling agentand/or other components of the treatment fluids of the presentinvention. For example, the treatment fluids of the present inventionmay comprise an ester that releases an acid once placed downhole that iscapable of, inter alia, reducing the pH and/or viscosity of thetreatment fluid. After the pre-blended powders and the aqueous basefluid have been combined, crosslinking agents and/or other suitableadditives may be added prior to introduction into the well bore. Thoseof ordinary skill in the art, with the benefit of this disclosure willbe able to determine other suitable methods for the preparation of thetreatments fluids of the present invention.

The treatment fluids of the present invention may be used in anysubterranean operation wherein a fluid may be used. Suitablesubterranean operations may include, but are not limited to, drillingoperations, hydraulic fracturing treatments, sand control treatments(e.g., gravel packing), acidizing treatments (e.g., matrix acidizing orfracture acidizing), FRACPAC™ treatments, well bore clean-outtreatments, and other suitable operations where a treatment fluid of thepresent invention may be useful.

In certain embodiments, the methods of the present invention comprise:providing a treatment fluid that comprises an aqueous base fluid, agelling agent, and one or more organic acids; and contacting asubterranean formation with the treatment fluid at or above a pressuresufficient to create or enhance one or more fractures in a portion ofthe subterranean formation. In these embodiments, a treatment fluid ofthe present invention may be pumped into a well bore that penetrates asubterranean formation at a sufficient hydraulic pressure to create orenhance one or more cracks, or “fractures,” in the subterraneanformation. “Enhancing” one or more fractures in a subterraneanformation, as that term is used herein, is defined to include theextension or enlargement of one or more natural or previously createdfractures in the subterranean formation. The treatment fluids of thepresent invention used in these embodiments optionally may compriseparticulates, often referred to as “proppant particulates,” that may bedeposited in the fractures. The proppant particulates may function,inter alia, to prevent one or more of the fractures from fully closingupon the release of hydraulic pressure, forming conductive channelsthrough which fluids may flow to the well bore. Once at least onefracture is created and the proppant particulates are substantially inplace, the viscosity of the treatment fluid of the present invention maybe reduced (e.g., through the use of a gel breaker, or allowed to reducenaturally over time) to allow it to be recovered.

In certain embodiments, the methods of the present invention comprise:providing a treatment fluid that comprises an aqueous base fluid, aplurality of particulates, a gelling agent, and one or more organicacids; introducing the treatment fluid into at least a portion of asubterranean formation; and depositing at least a portion of theparticulates in a portion of the subterranean formation so as to form agravel pack in a portion of the subterranean formation. In theseembodiments, a treatment fluid of the present invention may suspend theplurality of particulates (commonly referred to as “gravelparticulates”), and deposit at least a portion of those particulates ina desired area in a subterranean formation, for example, in a portion ofa well bore near an unconsolidated or weakly consolidated area in theformation, to form a “gravel pack,” which is a grouping of particulatesthat are packed sufficiently close together so as to prevent the passageof certain materials through the gravel pack. This “gravel pack” may,inter alia, enhance sand control in the subterranean formation and/orprevent the flow of particulates from an unconsolidated portion of thesubterranean formation (e.g., a propped fracture) into a well bore. Incertain embodiments, a sand control screen may be placed in a portion ofa well bore penetrating the subterranean formation, and the annulusbetween the screen and the well bore may become packed withparticulates. These particulates may have a specific size designed toprevent the passage of formation sand and/or other materials in theformation. The particulates may act, inter alia, to prevent theformation particulates from occluding the screen or migrating with theproduced hydrocarbons, and the screen may act, inter alia, to preventthe particulates from entering the well bore. Once the particulates arenear or deposited in the desired portion of the subterranean formation,the viscosity of the treatment fluid of the present invention may bereduced (e.g., through the use of a gel breaker, or allowed to reducenaturally over time) to allow it to be recovered.

In certain embodiments, the methods of the present invention comprise:providing a treatment fluid that comprises an aqueous base fluid, agelling agent, one or more organic acids or salts thereof, and one ormore inorganic acids or salts thereof; and allowing at least a portionof the treatment fluid to react with at least a portion of asubterranean formation so that at least one void is formed in thesubterranean formation. In these embodiments, a portion of thesubterranean formation is contacted with a treatment fluid of thepresent invention comprising one or more organic acids (or saltsthereof) and one or more inorganic acids (or salts thereof), whichinteract with subterranean formation to form “voids” (e.g., cracks,fractures, wormholes, etc.) in the formation. After acidization iscompleted, the treatment fluid of the present invention (or some portionthereof) may be recovered to the surface. The remaining voids in thesubterranean formation may, inter alia, enhance the formation'spermeability, and/or increase the rate at which fluids subsequently maybe produced from the formation. In certain embodiments, a treatmentfluid of the present invention may be introduced into the subterraneanformation at or above a pressure sufficient to create or enhance one ormore fractures within the subterranean formation. In other embodiments,a treatment fluid of the present invention may be introduced into thesubterranean formation below a pressure sufficient to create or enhanceone or more fractures within the subterranean formation.

In certain embodiments, the methods of the present invention comprise:providing a treatment fluid comprising an aqueous base fluid, a gellingagent, and one or more organic acids; introducing the treatment fluidinto a subterranean formation; and allowing the treatment fluid tosuspend one or more particulates in the subterranean formation. In theseembodiments, the treatment fluid may be used in any subterraneanoperation where it is desirable to suspend one or more particulates(e.g., proppant particulates, formation fines, gravel particulates,etc.) in the fluid. In certain embodiments, the treatment fluid may beused in clean-out operations, wherein the treatment fluid may becirculated in the subterranean formation, thereby suspendingparticulates residing in the formation in the treatment fluid. Thetreatment fluid then may be recovered out of the formation, carrying thesuspended particulates with it. In certain embodiments, the treatmentfluid may be introduced into and/or circulated in a subterraneanformation in the course of drilling a portion of a well bore in asubterranean formation, wherein the treatment fluid may suspendparticulate cuttings generated from the drilling process. In certainembodiments, once the treatment fluid has been allowed to suspend one ormore particulates in the subterranean formation, the treatment fluid maybe recovered (e.g., by “flowing back” the well) from the formation.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit or define thescope of the invention.

EXAMPLES Example 1

Samples of two artificially-spent acid treatment fluids having thefollowing compositions were prepared in a Waring blender: Fluid Sample 1contained 196 mL of an aqueous solution composed of 0.2% by volumeformic acid and 0.4% by volume hydrochloric acid to which was added 4 mLof an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium methylsulfate copolymer gelling agent. Fluid Sample 2 contained 196 mL of anaqueous solution composed of 2% by volume hydrochloric acid to which wasadded 4 mL of an acrylamide/2-(methacryloyloxy)ethyltrimethylammoniummethyl sulfate copolymer gelling agent. The pH of each sample was thenadjusted to ˜pH 3 with a 40% by weight potassium carbonate buffersolution. The viscosity of each sample were observed and recorded usinga Fann® Model 50 viscometer with a Hastalloy B5X bob and standard sleeveusing a No. 1 spring. The Model 50 viscometer test procedure thatfollowed was a modified API2 program that consisted of 118/29/88 rpmramping scan with 88 rpm as the base. When the sample reached the targettemperature, it performed its first ramping scan. Thereafter, rampingscans occurred every 10 to 15 minutes. Each ramping scan provided shearsat 118 rpm (100 s⁻¹), 88 rpm (75 s⁻¹), 59 rpm (50 s⁻¹), and 29 rpm (25s⁻¹), then back to 59, 88, and 118 rpm before settling to 88 rpm. At theend of the test, the data was collected and the time averaged. A plot oftime (min) versus viscosity (cP) and temperature (° F.) for each sampleis provided in FIG. 1.

Thus, Example 1 illustrates that the treatment fluids of the presentinvention may maintain higher viscosities at higher temperatures and/orfor longer periods of time than conventional treatment fluids.

Example 2

Samples of two artificially-spent acid treatment fluids having thefollowing compositions were prepared in a Waring blender: Fluid Sample 3contained 194.7 mL of an aqueous solution composed of 0.2% by volumeformic acid and 0.4% by volume hydrochloric acid to which was added 4 mLof an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium methylsulfate copolymer gelling agent, 0.4 mL of a glycolic acid buffer, and0.9 mL of a crosslinking agent solution (aqueous solution of 60% byweight ferric chloride). Fluid Sample 4 contained 194.7 mL of an aqueoussolution composed of 2% by volume hydrochloric acid to which was added 4mL of an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium methylsulfate copolymer gelling agent, 0.4 mL of a glycolic acid buffer, and0.9 mL of a crosslinking agent solution (aqueous solution of 40% byweight ferric chloride). 0.096 grams of a ferric iron inhibitor(Ferchek®, available from Halliburton Energy Services, Duncan, Okla.)was then added to each fluid sample. The pH of each sample was thenadjusted to ˜pH 3 with a 40% by weight potassium carbonate buffersolution. The viscosity of each sample were observed and recorded usinga Fann® Model 50 viscometer with a Hastalloy 35X bob and standard sleeveusing a No. 1 spring. The Model 50 viscometer test procedure thatfollowed was a modified AP2 program that consisted of 118/29/88 rpmramping scan with 88 rpm as the base. When the sample reached the targettemperature, it performed its first ramping scan. Thereafter, rampingscans occurred every 10 to 15 minutes. Each ramping scan provided shearsat 118 rpm (100 s⁻¹), 88 rpm (75 s⁻¹), 59 rpm (50 s⁻¹), and 29 rpm (25s⁻¹), then back to 59, 88, and 118 rpm before settling to 88 rpm. At theend of the test, the data was collected and the time averaged. A plot oftime (min) versus viscosity (cP) and temperature (° F.) for each sampleis provided in FIG. 2.

Thus, Example 2 illustrates that the treatment fluids of the presentinvention may maintain higher viscosities at higher temperatures and/orfor longer periods of time than conventional treatment fluids.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof this invention as defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present invention. In particular, every range ofvalues (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

1. A method comprising: providing a treatment fluid that comprises anaqueous base fluid, a plurality of particulates, a gelling agent, andone or more organic acids; introducing the treatment fluid into at leasta portion of a subterranean formation; and depositing at least a portionof the particulates in a portion of the subterranean formation so as toform a gravel pack in a portion of the subterranean formation.
 2. Themethod of claim 1 wherein the organic acid is selected from the groupconsisting of formic acid, acetic acid, citric acid, glycolic acid,lactic acid, 3-hydroxypropionic acid, any derivative thereof, and anycombination thereof.
 3. The method of claim 1 wherein the gelling agentcomprises at least one gelling agent selected from the group consistingof guar gums, celluloses, any derivative thereof, and any combinationthereof.
 4. The method of claim 1 wherein the gelling agent comprises asynthetic cationic gelling agent.
 5. The method of claim 1 wherein thegelling agent comprises at least one gelling agent selected from thegroup consisting of acrylamide/2-(methacryloyloxy)ethyltrimethylammoniummethyl sulfate copolymers,acrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloridecopolymers, any derivative thereof, and any combination thereof.
 6. Themethod of claim 1 wherein the gelling agent comprises a crosslinkedgelling agent.
 7. The method of claim 1 wherein the treatment fluidfurther comprises one or more crosslinking agents.
 8. The method ofclaim 1 wherein the treatment fluid further comprises one or more saltsof one or more organic acids selected from the group consisting ofsodium acetate, sodium formate, calcium acetate, calcium formate, cesiumacetate, cesium formate, potassium acetate, potassium formate, magnesiumacetate, magnesium formate, zinc acetate, zinc formate, antimonyacetate, antimony formate, bismuth acetate, bismuth formate, anyderivative thereof, and any combination thereof.
 9. The method of claim1 wherein the treatment fluid further comprises one or more inorganicacids or salts thereof.
 10. The method of claim 9 wherein the one ormore inorganic acids comprise one or more inorganic acids selected fromthe group consisting of hydrochloric acid, hydrofluoric acid,hydrobromic acid, sulfuric acid, phosphoric acid, nitric acid, anyderivative thereof, and any combination thereof.
 11. The method of claim9 wherein the one or more salts of the one or more inorganic acidscomprise at least one salt selected from the group consisting of sodiumchloride, calcium chloride, potassium chloride, sodium bromide, calciumbromide, potassium bromide, sodium sulfate, calcium sulfate, sodiumphosphate, calcium phosphate, sodium nitrate, calcium nitrate, cesiumchloride, cesium sulfate, cesium phosphate, cesium nitrate, cesiumbromide, potassium sulfate, potassium phosphate, potassium nitrate, anyderivative thereof, and any combination thereof.
 12. A methodcomprising: providing a treatment fluid that comprises an aqueous basefluid, a synthetic cationic gelling agent, a plurality of particulates,and one or more organic acids; introducing the treatment fluid into atleast a portion of a subterranean formation, wherein the viscosity ofthe treatment fluid in the subterranean formation is greater than about20 cP; and depositing at least a portion of the particulates in aportion of the subterranean formation so as to form a gravel pack in aportion of the subterranean formation.
 13. The method of claim 12wherein the organic acid comprises at least one gelling agent selectedfrom the group consisting of formic acid, acetic acid, citric acid,glycolic acid, lactic acid, 3-hydroxypropionic acid, any derivativethereof, and any combination thereof.
 14. The method of claim 12 whereinthe treatment fluid further comprises one or more crosslinking agents.15. The method of claim 12 wherein the treatment fluid further comprisesone or more salts of one or more organic acids selected from the groupconsisting of sodium acetate, sodium formate, calcium acetate, calciumformate, cesium acetate, cesium formate, potassium acetate, potassiumformate, magnesium acetate, magnesium formate, zinc acetate, zincformate, antimony acetate, antimony formate, bismuth acetate, bismuthformate, any derivative thereof, and any combination thereof.
 16. Themethod of claim 12 wherein the treatment fluid further comprises one ormore inorganic acids or salts thereof.
 17. The method of claim 16wherein the one or more inorganic acids comprise one or more inorganicacids selected from the group consisting of hydrochloric acid,hydrofluoric acid, hydrobromic acid, sulfuric acid, phosphoric acid,nitric acid, any derivative thereof, and any combination thereof. 18.The method of claim 16 wherein the one or more salts of the one or moreinorganic acids comprise at least one salt selected from the groupconsisting of sodium chloride, calcium chloride, potassium chloride,sodium bromide, calcium bromide, potassium bromide, sodium sulfate,calcium sulfate, sodium phosphate, calcium phosphate, sodium nitrate,calcium nitrate, cesium chloride, cesium sulfate, cesium phosphate,cesium nitrate, cesium bromide, potassium sulfate, potassium phosphate,potassium nitrate, any derivative thereof, and any combination thereof.19. A method comprising: providing a treatment fluid that comprises anaqueous base fluid, a gelling agent, and one or more organic acids orsalts thereof; introducing the treatment fluid into a subterraneanformation; and allowing the treatment fluid to suspend one or moreparticulates in the subterranean formation.
 20. The method of claim 19wherein the particulates are proppant or gravel particulates.